When a fluid, such as oil and natural gas, is being produced from a subterranean reservoir, the reservoir may not have sufficient energy, or the reservoir strata may have insufficient fluid conductivity, to eject fluids to the surface at a commercial fluid flow rates. A conventional method to recover fluids from a reservoir that has inadequate fluid conductivity is hydraulic fracturing. This hydraulic fracture treatment often allows reservoir fluids to be recovered at commercial rates. This benefit, however, is typically only temporary because fluid production to the surface will usually decline as fluids are extracted from the reservoir. In the case of a reservoir producing natural gas, the reservoir energy is normally depleted until it no longer ejects all the fluids out of the well.
As the fluids begin to accumulate in the well due to decreased flow conductivity, this accumulation further causes a hydrostatic fluid pressure that is exerted against the pressure of the subterranean reservoir, thereby reducing the flow of fluid to the surface. With time, this condition will eventually cause the well to stop producing fluid to the surface.
Another known method to increase fluid production is to insert a smaller conduit known as a velocity string into the well casing, to allow fluids to rise to the surface at a higher velocity. Higher fluid velocity has been found to increase the amount of fluid that can be lifted out of a well. Generally, both these methods may be combined to improve production of a low fluid conductivity reservoir. For instance, a reservoir may be hydraulically fractured then a velocity string may be inserted coaxially inside the casing to produce additional well fluids up the velocity string.
As mentioned above, increased fluid production from a hydraulically fractured well having a velocity string is not maintained indefinitely. Instead, as the reservoir pressure continues to be depleted during fluid extraction, the fluid velocity in the coaxially inserted velocity string becomes insufficient to lift the well fluids to the surface at a commercial production rate. Consequently, fluids begin to accumulate in the well and once again exert a hydrostatic pressure against the reservoir. While, additional smaller velocity strings can be coaxially inserted to increase fluid velocity, this method has its drawbacks. For instance, each new smaller velocity string reduces the fluid flow rates to the surface due to the increasing fluid friction in the velocity string as the diameter decreases. Further, inserting additional velocity strings does not address the decreasing reservoir energy as a reservoir is depleted of fluids, where the reservoir energy continues to decrease until it is insufficient to lift fluids to the surface at commercial rates.
Moreover, inserting additional velocity strings is inconvenient and not commercially expedient because to use the well configuration that was lastly deployed rather than extracting the final well configuration with an expensive rig intervention only to deploy some other configuration for further extracting well fluids at the current conditions. At this point in the life of a well generally known method of artificial lift is used to further extract fluid from the reservoir without substantially changing the well configuration, i.e., without pulling the last velocity string that was disposed in the well.
The known artificial lift pumping methods of the prior art were originally developed to extract oil and water from subterranean reservoirs. As such, these known artificial lift methods may not be best suited for extracting fluids from gas wells. There is still a need for applicable artificial lift means to operate in natural gas wells to assist in removing the fluids from such wells as the reservoir energy and correspondingly fluid flow velocities decrease to allow for commercial quantities of natural gas to be produced. Moreover, as natural gas wells are constructed deeper and deeper with more well bore deviation (indeed even horizontal orientations in such well bores are used through subterranean reservoirs), the need for a suitable means to lift fluids from the gas wells has increased.
There are various conventional artificial lift devices and methods, particularly used in the oil and gas industry, including gas lift, electrical submersible centrifugal pump systems, surface beam pumps with down hole traveling valves, surface electrical motors rotating rods from surface and attached to a well progressive cavity pump, hydraulic jet pumps, hydraulic piston pumps.
Also, the conventional hydraulic submersible artificial lift methods often involve the use of positive displacement piston pumps located at the surface to power the down hole hydraulic motors, engines, and pumps. An example of such pumps is disclosed in U.S. Pat. No. 2,081,221 to Clarence J. Coberly. These conventional systems of hydraulically lifting fluids from oil and gas wells introduce significant environmental hazards because they place high pressure hydraulic positive displacement piston pump systems at the surface.
It is further known to those familiar with producing oil and gas wells with hydraulic pumping systems that the use of water as a power fluid is limited in cold climates. The power water fluid is often heated or treated with freeze depressant chemicals to avoid freezing. This has many disadvantages, including extra energy use and the possibility of introducing hazardous chemicals into the environment.
The field of dewatering gas wells or as it is often known in the oil and gas industry as artificial lifting gas wells, is reluctant to adopt the current methods of hydraulic powered submersible hydraulic motors, engines, compressors, and pumps as most are currently powered by surface positive displacement piston pump systems. These conventional art uses of surface located positive displacement systems are dangerous and often outlawed by city ordinances for many reasons. In particular, there are likely risks associated with these systems, such as over pressurization of the surface equipment when a well hydraulic fluid system plugs, or a surface valve closes on the positive displacement tri-plex pumps discharge side, which causes a high pressure release of hydraulic power fluid.
Further, the conventional positive displacement pumps placed at the surface have large dimensions that cannot easily be accommodated in a well conduit and hence are located on the surface of the earth or at best on small skids with fluid containments beneath them. This configuration also introduces risks both at the surface environment and into a hydraulic power system, as an inadvertent closure of a valve, or the plugging of a valve, can cause a rapid pressure rise in the positive displacement pumps discharge often resulting in a catastrophic rupture and leak of the hydraulic power system. This catastrophic pressure rupture causes oil spills, fires, pollution, and danger to humans. Additionally, the conventional hydraulic power pumps surface arrangements have packing, and oil lubricants in their power ends that can leak and spill oil on the earth's surface. Hence the conventional hydraulic pumping system for lifting fluids from wells have many drawbacks including continual and frequent oil changes, and pump maintenance further introducing the opportunity to have an oil spill at the surface.
Additional drawbacks include a large surface footprint, which makes the conventional systems difficult to house or encapsulate to contain leaks from the pump system. What is needed is a method to hydraulically power submersible hydraulic motors with a hydraulic power systems that can be disposed below the surface in a containment means to avoid oil spills, and dangers if such a high pressure pump catastrophically fails.
In view of the disadvantages of the current system, there is a need for a hydraulic power pumping system that does not involve positive displacement pumps located at the surface to address the drawbacks of current systems such as frequent lubricant changes, lubricant additions; catastrophic conduit failure caused by valve closure or conduit plugging; and heating or treating operating fluid functional in cold climates.